Pressure-compensated flow shut-off sleeve for wellhead and subsea well assembly including same

ABSTRACT

A flow shut-off sleeve assembly adapted to be coupled to a subsea wellhead housing disposed within a conductor housing, which opens and closes at least one flow port in the conductor housing to annular fluid flow, is provided. The flow shut-off sleeve assembly includes an internal annular flow shut-off sleeve disposed around an exterior portion of the subsea wellhead housing and an external annular flow shut-off sleeve disposed around an exterior portion of the internal annular flow shut-off sleeve. The external annular flow shut-off sleeve is movable axially relative to the internal annular flow shut-off sleeve between an open position wherein the at least one flow port is open to annular fluid flow and a closed position, wherein the at least one flow port is closed to annular fluid flow. A subsea well assembly is also provided, which includes the flow shut-off sleeve assembly.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application No.60/583,323 filed on Jun. 28, 2004.

FIELD OF THE INVENTION

The present invention relates generally to flow shut-off sleeves for usein oil and gas wells, and more particularly to a flow shut-off sleevethat can provide pressure-compensated shut-off for a surface or subseawellhead.

BACKGROUND

A common offshore technique involves drilling a first section of thehole and installing conductor pipe, or jetting in the conductor pipe,with an external wellhead housing at the upper end. The externalwellhead housing will be located approximately at the sea floor. Then,the operator drills the well to a second depth and installs a firstsection of casing. An internal or high-pressure wellhead housing isusually located at the upper end of the first string of casing. Thisfirst string of casing will be cemented in the well, with cement returnsflowing up around the casing, through the conductor pipe and out flowports located in the external wellhead housing. These flow ports remainopen after cementing.

The operator retrieves the running tool for the internal wellheadhousing and connects a drilling riser and blowout preventer to theinternal wellhead housing. The operator will then drill the well togreater depths and normally install at least two more strings of casing.Each string of casing has a casing hanger at its upper end which willland and seal in the internal wellhead housing.

As shown in FIGS. 7A and 7B, in some areas, the conventional techniquedescribed above is not satisfactory. For example, one area in the Gulfof Mexico has an over pressured sand formation 700 approximately500-1000 feet below the sea bed 702. This formation has a pressure thatis higher than the pressure at the sea floor by approximately 50-250pounds per square inch (psi). When drilled into, the formation 708 tendsto wash out, with water and sand flowing upward 704 to the sea floor702. If the shallow water flow 704 is not contained, structuralintegrity of the conductor pipe 706 will be compromised.

Various techniques have been employed to overcome the shallow water flowproblem. A cement is available that is of a foaming-type that can beemployed to retard washout. U.S. Pat. No. 5,184,686 discloses a systemfor avoiding washout. However, that system requires using two differentsize drilling risers at various stages of the drilling. This makes thetechnique very expensive.

In another prior art system, as shown, for example, in FIGS. 1 and 2 ofU.S. Pat. No. 5,660,234, incorporated by reference herein, an externalwellhead housing 19 has a number of flow ports 21. An external valvesleeve 23 mounts to the exterior of the external wellhead housing 19.The external valve sleeve 23 is axially movable between an open position(FIG. 1 of U.S. Pat. No. 5,660,234) and a closed position (FIG. 2 ofU.S. Pat. No. 5,660,234), blocking flow through the flow ports 21.However, the external valve sleeve 23 is mounted to the exterior of theexternal wellhead housing 19 and the elastomer seal is exposed toincreased wear and possible damage from cement returns and/or waterflowing conditions, as shown by the damaged seal 125 in FIG. 1A.

As shown, for example, in FIG. 2 of U.S. Pat. No. 5,660,234, mud mat 11is a type of a base that locates on the sea floor 12. The well may bejetted to a first depth, normally a few hundred feet, and conductor pipe13 installed. The conductor pipe 13, normally about 36 inches indiameter, may be installed in a conventional manner. The mud mat 11 maybe carried to the sea floor 12 as the conductor pipe 13 is installed.The conductor pipe 13 is supported on the mud mat 11 by a landing sub15. The landing sub 15 is a tubular member that latches into the mud mat11 and is connected into the conductor pipe 13.

The conductor pipe 13 has an extension 17 that extends above the landingsub 15 a few feet to support an external or low-pressure wellheadhousing 19. The external wellhead housing 19 is a large tubular memberhaving a plurality of flow ports 21 spaced around its circumference. Anexternal valve sleeve 23 mounts slidably to the exterior of the externalwellhead housing 19. The external valve sleeve 23 has seals 24 and maymove between an open position, as shown in FIG. 2 of U.S. Pat. No.5,660,234, to a closed position, as shown in FIG. 3 of U.S. Pat. No.5,660,234. When moved downward to the closed position, the externalvalve sleeve 23 will block any flow through the flow ports 21. Theexternal valve sleeve 23 may be in the open position initially.

After the installation of the external wellhead housing 19, the drillingrig at the surface of the sea may drill the well to a second depth. Thissecond depth will stop a short distance above water-producing formation25, for example, about 200 feet. The water-producing formation 25 is aloose, unconsolidated sand formation that produces water and has aformation pressure that is about 50-250 pounds per square inch (psi)greater than the pressure at the sea floor 12. Without precautions,water and sand from the water-producing formation 25 will flow up thewell to the sea floor 12 and wash out the well to a very large diameter.Consequently, the operator will terminate drilling the second phase ofthe well at a point above the water-producing formation 25.

The operator then installs a first string of casing 27. In one exemplaryembodiment, the casing 27 is 26 or 28 inches in diameter and issupported by a scab hanger 29 at its upper end. The operator cements thecasing 27 in place, as indicated by numeral 31. The cementing operationis conventional. While pumping cement, the operator may position thescab hanger 29 a short distance above its landing profile to allowcement returns to flow up and out the flow ports 21. The operator mayland and seal the scab hanger 29 in an internal profile in the landingsub 15 below the external wellhead housing 19. A split ring 30 on thescab hanger 29 latches into a groove in the landing sub 15 to retain thescab hanger 29 to the landing sub 15. The split ring 30 is released tosnap into the groove by the running tool (not shown in U.S. Pat. No.5,660,234) for the scab hanger 29. An annulus seal is installed betweenthe scab hanger 29 and the landing sub 15.

After the cement has set, the operator then drills a pilot hole (notshown in U.S. Pat. No. 5,660,234) through the water-producing formation25, terminating a short distance below the water-producing formation 25.The pilot hole may be about 12.25 inches in diameter, and known drillingfluid additives may be employed to retard washout in the water-producingformation 25. After drilling, the operator swabs the pilot hole with afoaming-type cement. The foaming-type cement permeates the loose sand,creating a hardened mud cake annulus in the well to retard washout. Theoperator then reams out this third section of the well to approximately23 to 26 inches in diameter.

The third hole section is indicated by numeral 33. It is large enough toaccept a second string of casing 35 which is preferably about 20 inchesin diameter. The second string of casing 35 has an internal orhigh-pressure wellhead housing 37 at its upper end. The internalwellhead housing 37 is of a conventional type and inserts within theexternal wellhead housing 19 generally as shown in U.S. Pat. No.5,029,647, Jul. 19, 1991. The external valve sleeve 23 is mounted to theexterior of the external wellhead housing 19 and may be exposed toincreased wear and damage during cementing operations. Furthermore, theexternal valve sleeve 23 is mounted to the exterior of the externalwellhead housing 19 throughout the drilling operations that lead up tothe installation and landing of the internal wellhead housing 37, andmay become closed inadvertently during those or other prior drillingoperations.

In still another prior art system, as shown in FIGS. 1 and 2, ahigh-pressure wellhead housing 119 has a number of flow ports 121. Aninternal valve sleeve 123 mounts to the exterior of the high-pressurewellhead housing 119, between the exterior of the high-pressure wellheadhousing 119 and an interior surface of a conductor housing 130 attachedto a conductor pipe 118. The internal valve sleeve 123 is axiallymovable between an open position (FIG. 1), which permits flow, indicatedby arrows 143, through the flow ports 121, and a closed position (FIG.2), blocking the flow 143 through the flow ports 121, causing a pressureuplift and/or buildup, indicated by arrows 243.

For example, a running tool 139 (shown in phantom) may cause a skirt 141(shown in phantom) to press down on an ear 129 of an actuator sleeve128, causing the actuator sleeve 128 to actuate an actuator rod 127,causing the internal valve sleeve 123, along with associated seals 125and 126, to move axially from the open position, as shown in FIG. 1,which permits the flow 143 through the flow ports 121, to the closedposition, as shown in FIG. 2, which blocks the flow 143 through the flowports 121, causing the pressure uplift 243.

After the internal valve sleeve 123 has closed the flow ports 121, theoperator may retrieve the running tool 139 and, as shown in FIG. 2,connect a drilling riser 245 that includes a blowout preventer. Theoperator may then drill the well to greater depths, installingadditional strings of casing. These strings of casing may be supportedand sealed by casing hangers that land conventionally within thehigh-pressure wellhead housing 119. However, the internal valve sleeve123 is not pressure-compensated and/or pressure-balanced and may beexposed to pressure uplift 243 when in the closed position, possiblyleading to ratchet failure and/or flow 143 through the flow ports 121,potentially causing detrimental well washout. Similar problems arebelieved to arise with the internal valve sleeve assembly available fromFMC Subsea Drilling System as the Rigid-Lock Annulus Seal Assembly.

SUMMARY

The present invention is directed to a pressure-compensated flowshut-off sleeve assembly that overcomes or at least minimizes some ofthe drawbacks of prior art valve sleeves.

In one illustrative embodiment, a flow shut-off sleeve assembly adaptedto be coupled to a subsea wellhead housing disposed within a conductorhousing, which opens and closes at least one flow port in the conductorhousing to annular fluid flow is provided. As used herein, the terms“couple,” “couples,” “coupled” or the like, are intended to mean eitherindirect or direct connection. Thus, if a first device “couples” to asecond device, that connection may be through a direct connection orthrough an indirect connection via other devices or connectors. The flowshut-off sleeve assembly includes an internal annular flow shut-offsleeve disposed around an exterior portion of the subsea wellheadhousing and an external annular flow shut-off sleeve disposed around anexterior portion of the internal annular flow shut-off sleeve. Theexternal annular flow shut-off sleeve is movable axially relative to theinternal annular flow shut-off sleeve between an open position whereinthe at least one flow port is open to annular fluid flow and a closedposition, wherein the at least one flow port is closed to annular fluidflow.

The internal annular flow shut-off sleeve may include at least one firstopening disposed therein and the external annular flow shut-off sleevemay include at lest one second opening disposed therein. In the openposition, the at least one first opening of the internal annular flowshut-off sleeve is substantially aligned with the at least one secondopening of the external annular flow shut-off sleeve. In the closedposition, the at least one first opening of the internal annular flowshut-off sleeve is substantially nonaligned with the at least one secondopening of the external annular flow shut-off sleeve. A shearableattachment, which secures the internal annular flow shut-off sleeve tothe external annular flow shut-off sleeve temporarily in the openposition, may also be provided. The shearable attachment hold the flowshut-off sleeves in the open position during landing. At least one shearscrew may be provided to substantially permanently secure the internalannular flow shut-off sleeve to the external annular flow shut-offsleeve after annular fluid has passed through the at least one flow portand the flow shut-off sleeves have been moved to the closed position.

In another illustrative embodiment, a subsea well assembly including theflow shut-off sleeve according to the present invention is provided. Thesubsea well assembly includes a subsea wellhead housing coupled to astring of casing extending through a string of conductor pipe. Theconductor pipe is coupled to a conductor housing. The conductor housinghas a sidewall including at least one flow port and a support profile.The support profile supports the subsea wellhead housing and the stringof casing. The subsea well assembly further includes the flow shut-offsleeve assembly according to the present invention. The internal annularflow shut-off sleeve of the assembly is disposed around an exteriorportion of the subsea wellhead housing.

BRIEF DESCRIPTION OF THE DRAWINGS

A complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings, in which the leftmostsignificant digit(s) in the reference numerals denote(s) the firstfigure in which the respective reference numerals appear, wherein:

FIG. 1 schematically illustrates a longitudinal sectional view of aconventional subsea wellhead system showing the landing of ahigh-pressure wellhead housing, with flow ports open and internal valvesleeve in an open position.

FIG. 1A is an enlarged view of the external valve sleeve and damagedelastomer seal shown in FIG. 1.

FIG. 2 schematically illustrates another longitudinal sectional view ofthe conventional subsea wellhead system of FIG. 1, with flow portsclosed and the internal valve sleeve in a closed position.

FIG. 3 schematically illustrates a longitudinal sectional view of asubsea wellhead system according to various embodiments of a method anda device of the present invention, showing the landing of ahigh-pressure wellhead housing, with flow ports open and an internalannular flow shut-off sleeve and an external annular flow shut-offsleeve in an open position.

FIG. 4 schematically illustrates another longitudinal sectional view ofthe subsea wellhead system of FIG. 3, after landing and installation ofthe high-pressure wellhead housing, with the flow ports open and theinternal and external annular flow shut-off sleeves in an open position.

FIG. 5 schematically illustrates another longitudinal sectional view ofthe subsea wellhead system of FIGS. 3 and 4, with flow ports closed andthe internal and external annular flow shut-off sleeves in a closedposition.

FIG. 6 schematically illustrates another longitudinal sectional view ofthe subsea wellhead system of FIG. 3, after landing and installation ofthe high-pressure wellhead housing, with the flow ports permanently openand the internal and external annular flow shut-off sleeves in apermanently open and/or disabled position.

FIGS. 7A and 7B illustrates the phenomenon of washout that can occur inover pressured sand formations.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments of the invention are described in detail below.In the interest of clarity, not all features of an actual implementationare described in this specification. It will of course be appreciatedthat in the development of any such actual embodiment, numerousimplementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which will vary from one implementation toanother. Moreover, it will be appreciated that such a development effortmight be complex and time-consuming, but would nevertheless be a routineundertaking for those of ordinary skill in the art having the benefit ofthis disclosure.

The details of the present invention will now be described withreference to the figures. As shown in FIG. 3, a running tool 339 (shownin phantom) may be employed to apply a large axial force to install ahigh-pressure internal wellhead housing 319 secured to a string ofcasing 320 extending through a string of conductor pipe 318 attached toa conductor housing 330. The conductor housing 330 may have a sidewall331 including a plurality of flow ports 321 and a support profile 340,the support profile 340, for example, supporting a support element 335secured to an exterior portion of the subsea high-pressure wellheadhousing 319, thereby supporting the subsea high-pressure wellheadhousing 319 and the string of casing 320. In various illustrativeembodiments, the size of the flow ports 321 may be in a range of about 3inches to about 4 inches in diameter. In various exemplary illustrativeembodiments, the size of the flow ports 321 may be about 3.5 inches indiameter.

An internal annular flow shut-off sleeve 324 may be secured to anexterior portion of the subsea high-pressure wellhead housing 319. Theinternal annular flow shut-off sleeve 324 may have a plurality of firstopenings 350 disposed therein. In various illustrative embodiments, thesize of the first openings 350 may be in a range of about 1 inch toabout 2.5 inches in diameter. In various exemplary illustrativeembodiments, the size of the first openings 350 may be about 1.25 inchesin diameter.

An external annular flow shut-off sleeve 323 may be releasably mountedto an exterior portion of the internal annular flow shut-off sleeve 324.In various illustrative embodiments, the external annular flow shut-offsleeve 323 may be releasably mounted to an exterior portion of theinternal annular flow shut-off sleeve 324 with at least one shearableattachment 322 to the exterior portion of the internal annular flowshut-off sleeve 324. The shearable attachment 322 may include one ormore shear pins and/or shear screws, each capable of shearing at about2255 pounds (lbs) of force, for example. In various illustrativeembodiments, for example, the shearable attachment 322 may include asufficient number of shear pins and/or shear screws to be able towithstand a total shearing force of up to about 50,000 pounds (lbs). Invarious exemplary illustrative embodiments, the shearable attachment 322may include about six shear pins and/or shear screws, each capable ofshearing at about 2255 pounds (lbs) of force, requiring a total shearingforce of about 13,530 pounds (lbs), for example.

The external annular flow shut-off sleeve 323 may have a plurality ofsecond openings 355 disposed therein. In various illustrativeembodiments, the size of the second openings 355 disposed in theexternal annular flow shut-off sleeve 323 may be substantially the same,or substantially similar to, the size of the first openings 350 disposedin the internal annular flow shut-off sleeve 324. In variousillustrative embodiments, the size of both the first and second openings350 and 355, respectively, may be in a range of about 1 inch to about2.5 inches in diameter. In various exemplary illustrative embodiments,the size of both the first and second openings 350 and 355,respectively, may be about 1.25 inches in diameter.

The external annular flow shut-off sleeve 323 may be movable axiallyrelative to the internal annular flow shut-off sleeve 324, the subseahigh-pressure wellhead housing 319, and the conductor pipe sidewall 331between an open position, as shown in FIG. 4, wherein the plurality offirst openings 350 of the internal annular flow shut-off sleeve 324 aresubstantially aligned with the plurality of second openings 355 of theexternal annular flow shut-off sleeve 323, exposing the plurality offlow ports 321, and a closed position, as shown in FIG. 5, wherein theplurality of first openings 350 of the internal annular flow shut-offsleeve 324 are not substantially aligned with the plurality of secondopenings 355 of the external annular flow shut-off sleeve 323, closingthe plurality of flow ports 321.

For example, as shown in FIG. 4, the running tool 339 (shown in phantom)may cause a skirt 441 (shown in phantom) to press down on an ear 429 ofan actuator sleeve 428, causing the actuator sleeve 428 to actuate anactuator rod 427, causing the external annular flow shut-off sleeve 323to move axially from the open position, which permits flow, indicated byarrows 443, through the substantially aligned pluralities of first andsecond openings 350 and 355, respectively, and through the flow ports421, to the closed position, as shown in FIG. 5, which blocks the flow443 through the substantially nonaligned pluralities of first and secondopenings 350 and 355, respectively, and through the flow ports 421,causing a pressure buildup or uplift, indicated by arrows 543. Thesealing of the first plurality of openings 350 of the internal annularflow shut-off sleeve is furthered by associated seals 425 and 426,disposed between in the internal annular flow shut-off sleeve 324 andthe external annular flow shut-off sleeve 323 adjacent the firstplurality of openings 350. In various illustrative embodiments, forexample, O-rings may be used for the seals 425 and/or 426. Theassociated seals 425 and 426 are disposed above and below the first andsecond plurality of openings 350 and 355 on a same diameter of theinternal annular flow shut-off sleeve 324. The external annular flowshut-off sleeve 323 is adapted to slide axially over the pair of seals425 and 426 to close off flow through the first and second plurality ofopenings 350 and 355. The associated seals 425 and 426 are pressurebalanced.

The closed position, as shown in FIG. 5, provides a pressure-compensatedand/or pressure-balanced flow shut-off sleeve and assembly for use witha subsea and/or subsurface wellhead. As long as the first and secondopenings 350 and 355 are substantially the same size and/or similar insize, the closed position, as shown in FIG. 5, provides apressure-compensated and/or pressure-balanced flow shut-off sleeve andassembly for use with a subsea and/or subsurface wellhead, capable ofresisting the pressure uplift 543.

The external annular flow shut-off sleeve 323 may be capable of beingsecured in a substantially permanently open position, as shown in FIG.6, substantially permanently exposing the plurality of flow ports 321.For example, in various illustrative embodiments, the external annularflow shut-off sleeve 323 may be secured in a substantially permanentlyopen position by unfastening and/or shearing the shearable attachment322 to the exterior portion of the internal annular flow shut-off sleeve324 and lowering the external annular flow shut-off sleeve 323 to adocking station 600 and locking in place with one or more shear screws622. Note that this arrangement allows access to, and replacement ifneeded, of the seals 425 and 426, which may be, for example, O-rings, invarious illustrative embodiments, as described above. This arrangementfurther allows removal of the shear screw or shear pin fragment leftafter the shearable attachment 322 to the exterior portion of theinternal annular flow shut-off sleeve 324 has been sheared.

After the internal and external annular flow shut-off sleeves 324 and323, respectively, have closed the flow ports 321, the operator mayretrieve the running tool 339 and, as shown in FIG. 5, connect adrilling riser 545 (shown in phantom) that includes a blowout preventer.The operator may then drill the well to greater depths, installingadditional strings of casing (not shown). These strings of casing may besupported and sealed by casing hangers that land conventionally withinthe high-pressure wellhead housing 319. Here, unlike with various priorart systems, since the assembly of the internal and external annularflow shut-off sleeves 324 and 323, respectively, is pressure-compensatedand/or pressure-balanced, even though the assembly of the internal andexternal annular flow shut-off sleeves 324 and 323, respectively, may beexposed to pressure uplift 543 when in the closed position, there ismuch less chance of a ratchet failure and/or return of the flow 443through the flow ports 321, substantially reducing the possibility ofpotentially causing a detrimental well washout.

Furthermore, the assembly of the internal and external annular flowshut-off sleeves 324 and 323, respectively, is not mounted to theinterior sidewall 331 of the conductor housing 330 throughout thedrilling operations that lead up to the installation and landing of thehigh-pressure wellhead housing 319, and, thus, cannot become closedinadvertently during those or other prior drilling operations, unlikewith various prior art systems. Rather, the assembly of the internal andexternal annular flow shut-off sleeves 324 and 323, respectively, ismounted to an exterior portion of the high-pressure wellhead housing 319and is, therefore, advantageously installed and landed when thehigh-pressure wellhead housing 319 is installed and landed.

In various alternative illustrative embodiments, an internal annularflow shut-off sleeve without any openings therein (not shown) may bemounted to a portion of the interior sidewall 331 of the conductorhousing 330. Such an internal annular flow shut-off sleeve without anyopenings therein may be axially movable between an open position (notshown), allowing flow through the flow ports 321, and a closed position(not shown), blocking flow through the flow ports 321. Such an internalannular flow shut-off sleeve, without any openings therein, mounted to aportion of the interior sidewall 331 of the conductor housing 330,advantageously would not be exposed to increased wear and damage fromcementing returns.

Therefore the present invention are well adapted to carry out theobjects and attain the ends and advantages mentioned, as well as thosethat are inherent therein. While the present invention has beendepicted, described, and defined by reference to exemplary embodimentsof the present invention, such a reference does not imply any limitationof the present invention, and no such limitation is to be inferred. Thepresent invention is capable of considerable modification, alteration,and equivalency in form and function as will occur to those of ordinaryskill in the pertinent arts having the benefit of this disclosure. Thedepicted and described illustrative embodiments of the present inventionare exemplary only and are not exhaustive of the scope of the presentinvention. Consequently, the present invention is intended to be limitedonly by the spirit and scope of the appended claims, giving fullcognizance to equivalents in all respects.

The particular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. Accordingly, the protection soughtherein is as set forth in the claims below.

1. A flow shut-off sleeve assembly adapted to be coupled to a subseawellhead housing disposed within a conductor housing, which opens andcloses at least one flow port in the conductor housing to annular fluidflow, the assembly comprising: an internal annular flow shut-off sleevedisposed around an exterior portion of the subsea wellhead housing; andan external annular flow shut-off sleeve disposed around an exteriorportion of the internal annular flow shut-off sleeve, the externalannular flow shut-off sleeve movable axially relative to the internalannular flow shut-off sleeve between an open position and a closedposition.
 2. The flow shut-off sleeve assembly according to claim 1,wherein the internal annular flow shut-off sleeve comprises at least onefirst opening disposed therein and the external annular flow shut-offsleeve comprises at least one second opening disposed therein.
 3. Theflow shut-off sleeve assembly according to claim 2, wherein the at leastone first opening of the internal annular flow shut-off sleeve issubstantially aligned with the at least one second opening of theexternal annular flow shut-off sleeve in the open position, and whereinthe at least one first opening of the internal annular flow shut-offsleeve is substantially nonaligned with the at least one second openingof the external annular flow shut-off sleeve in the closed position. 4.The flow shut-off sleeve assembly according to claim 2, wherein theexternal annular flow shut-off sleeve is capable of being secured in asubstantially permanently open position, wherein the at least one firstopening of the internal annular flow shut-off sleeve is substantiallyaligned with the at least one second opening of the external annularflow shut-off sleeve.
 5. The flow shut-off sleeve assembly according toclaim 4, wherein the external annular flow shut-off sleeve is secured tothe internal annular flow shut-off sleeve by at least one shear screw.6. The flow shut-off sleeve assembly according to claim 1, furthercomprising a pair of seals disposed between the internal annular flowshut-off sleeve and the external annular flow shut-off sleeve, whereinone of the pair of seals is disposed above the at least one firstopening and the other of the pair of seals is disposed below the atleast one first opening.
 7. The flow shut-off sleeve assembly accordingto claim 6, wherein the pair of seals comprises a pair of O-rings. 8.The flow shut-off sleeve assembly according to claim 1, furthercomprising a shearable attachment, which secures the external annularflow shut-off sleeve to the internal annular flow shut-off sleeve in atemporary open position.
 9. The flow shut-off sleeve assembly accordingto claim 1, further comprising an actuator means adapted to be coupledto a running tool and adapted to engage the external annular flowshut-off sleeve to cause it to move axially between the open positionand the closed position.
 10. The flow shut-off sleeve assembly accordingto claim 9, wherein the actuator means comprises an actuator sleevehaving an ear which is engaged by a skirt of the running tool and anactuator rod coupled to the actuator sleeve, which engages the externalannular flow shut-off sleeve.
 11. A subsea well assembly comprising: asubsea wellhead housing coupled to a string of casing extending througha string of conductor pipe, the conductor pipe coupled to a conductorhousing, the conductor housing having a sidewall including at least oneflow port and a support profile, the support profile supporting thesubsea wellhead housing and the string of casing; an internal annularflow shut-off sleeve disposed around an exterior portion of the subseawellhead housing; and an external annular flow shut-off sleeve disposedaround an exterior portion of the internal annular flow shut-off sleeve,the external annular flow shut-off sleeve movable axially relative tothe internal annular flow shut-off sleeve and the conductor pipesidewall between an open position, wherein the at least one flow port isopen to annular fluid flow, and a closed position, wherein the at leastone flow port is closed to annular fluid flow.
 12. The subsea wellassembly according to claim 11, wherein the internal annular flowshut-off sleeve comprises at least one first opening disposed thereinand the external annular flow shut-off sleeve comprises at least onesecond opening disposed therein.
 13. The subsea well assembly accordingto claim 12, wherein the at least one first opening of the internalannular flow shut-off sleeve is substantially aligned with the at leastone second opening of the external annular flow shut-off sleeve in theopen position, and wherein the at least one first opening of theinternal annular flow shut-off sleeve is substantially nonaligned withthe at least one second opening of the external annular flow shut-offsleeve in the closed position.
 14. The subsea well assembly according toclaim 12, wherein the external annular flow shut-off sleeve is capableof being secured in a substantially permanently open position, whereinthe at least one first opening of the internal annular flow shut-offsleeve is substantially aligned with the at least one second opening ofthe external annular flow shut-off sleeve.
 15. The subsea well assemblyaccording to claim 14, wherein the external annular flow shut-off sleeveis secured to the internal annular flow shut-off sleeve by at least oneshear screw.
 16. The subsea well assembly according to claim 11, furthercomprising a pair of seals disposed between the internal annular flowshut-off sleeve and the external annular flow shut-off sleeve, whereinthe pair of seals is disposed above and below the at least one first andsecond openings on a same diameter of the internal annular flow shut-offsleeve and wherein the external annular flow shut-off sleeve is adaptedto slide axially over the pair of seals to close off flow through the atleast one first and second openings.
 17. The subsea well assemblyaccording to claim 16, wherein the pair of seals comprises a pair ofO-rings disposed on the same diameter of the internal annular flowshut-off sleeve so as to make the pair of O-rings pressure balanced. 18.The subsea well assembly according to claim 11, further comprising ashearable attachment, which secures the external annular flow shut-offsleeve to the internal annular flow shut-off sleeve in a temporary openposition.
 19. The subsea well assembly according to claim 11, furthercomprising an actuator means adapted to be coupled to a running tool andadapted to engage the external annular flow shut-off sleeve to cause itto move axially between the open position and the closed position. 20.The subsea well assembly according to claim 19, wherein the actuatormeans comprises an actuator sleeve having an ear which is engaged by askirt of the running tool and an actuator rod coupled to the actuatorsleeve, which engages the external annular flow shut-off sleeve.